Many horizontal wells exhibit an early erratic production profile. This early flow regime is considered burst or slug flow but is seldom laminar or turbulent. Qualitative and quantitative analysis of the reservoir and fluid properties, based on the produced fluids during this early stage, can yield erroneous conclusions without a proper understanding of downhole borehole phenomena. This paper describes the varying nature of the oil, water, and gas rates.
The downhole flow dynamics of two fluid-type scenarios of volatile oil and gas condensates were modeled in a slightly heterogeneous reservoir drilled horizontally toe-up and toe-down. The reservoir section might be stimulated using hydraulic fracturing. The dynamic process described is heavily dependent on the lateral distribution of the wellbore-to-formation connectivity but is less dependent on the completion jewelry. The process assumes that the oil reaches the bubblepoint in the horizontal section of the well and that the reservoir pressure is greater than the hydrostatic fluid column.
The interpretation presented here is supported with systematic fluid diagrams and fundamental principles and corroborated by field examples. The interpretation indicates that reservoir and fluid types, in addition to tubular sizes, affect productivity in horizontal wells drilled toe-up and toe-down. The use of array production logging would validate these principles. Formation permeability, wellbore skin damage or stimulation, and reservoir pressure control the fluid-flow strength to the wellbore. Fluid types and the ratios of oil, gas, and water, along with bubblepoint and dewpoint pressures and wettability values, control the preferential flow to the wellbore. The tubular sizes act as a choke to the flow, affecting the fluid-flow type. This paper presents the effect of choke sizes on flow-rate stability and bottomhole flowing pressure (BHFP) as well as the minimum required flow rate to clean water and debris from the well.